Africa (Sub-Sahara) Drilling began on the Bamboo-1 well, located around 35 miles offshore Cameroon in the Ntem concession. The Bamboo prospect is a basin floor fan target within an Upper Cretaceous play. The well will be drilled to an estimated depth of 4200 m. Murphy Cameroon (50%) is the operator, with partner Sterling (50%). The Nene Marine 3 exploration well--located in the Marine XII block, which is around 17 km offshore Congo--encountered a wet gas and light oil accumulation in a presalt clastic sequence Eni (65%) operates the Marine XII block, with partners New Age (25%) and Société Nationale des Pétroles du Congo (10%). CNPC said PetroChina is now building a production facility capable of pumping 4 Bcm/yr.
Africa (Sub-Sahara) Bowleven began drilling operations at its Zingana exploration well on the Bomono permit in Cameroon. Located 20 km northwest of Douala, Cameroon's largest city, the well will target a Paleocene (Tertiary) aged, three-way dip closed fault block. The company plans to drill the well to a depth of 2000 m and will then spud a second well in Moambe, 2 km east of Zingana. Bowleven is the operator and holds 100% interest in the license. Asia Pacific China National Offshore Oil Company (CNOOC) has brought its Dongfang 1-1 gas field Phase I adjustment project on line ahead of schedule. The field is located in the Yinggehai basin of the Beibu Gulf in the South China Sea and has an average water depth of 70 m. The field is currently producing 53 MMcf/D of gas and is expected to reach its peak production of 54 MMcf/D before the end of the year.
Africa (Sub-Sahara) Bowleven has started drilling operations at the Moambe exploration well on the Bomono permit in Cameroon. Moambe is the second well in a two-well program, approximately 2 km east of the first well, Zingana. It targets a previously undrilled Paleocene Tertiary three-way dip fault block containing multiple sands and will be drilled to an estimated 1620 m in measured depth. Both wells will be logged. Bowleven is the operator and holds 100% interest. Asia Pacific Murphy Oil discovered gas at its Permai exploration well in deepwater Block H in the South China Sea offshore Malaysia. The find is Murphy's eighth consecutive success in the area around the Rotan floating liquefied natural gas project, which is planned to begin its first production in 2018.
Africa (Sub-Sahara) Bowleven's Moambe exploration well on the Bomono Permit onshore Cameroon has encountered hydrocarbons. The well was drilled to a planned total depth of 5,803 ft and made its discovery in Paleocene-aged (Tertiary) target reservoir intervals. Moambe is the second in a two-well exploration program on the permit. The first well, Zingana, also discovered hydrocarbons. The Moambe well will be tested before further testing takes place at Zingana. Bowleven holds 100% interest in the permit. Shell Nigeria Exploration and Production has begun production at the Bonga Phase 3 project, an expansion of the deepwater Bonga project in Nigeria. Peak production from the expansion is expected to be 50,000 BOEPD, which will be shipped by pipelines to the Bonga floating production, storage, and offloading facility.
Africa (Sub-Sahara) Eni started production from the West Hub development project's Mpungi field in Block 15/06 offshore Angola. The startup follows the project's first oil from the Sangos field in November 2014 and the Cinguvu field last April. Mpungi will ramp up West Hub oil production to 100,000 B/D in the first quarter from a previous level of 60,000 B/D. The project also includes the future development of the Mpungi North, Ochigufu, and Vandumbu fields. Eni is the block operator with a 36.84% stake. Sonangol (36.84%) and SSI Fifteen (26.32%) hold the other stakes.
In the Freeman Field, located about 120km offshore southwestern Niger Delta at about 1300m water depth, 3D seismic attribute-based analogs, and structural and stratigraphic based geometric models are combined to help enhance and constrain interpretation. The objective of this research was to aid in the prospecting of Miocene to Pliocene Agbada Formation reservoirs in the deep offshore Niger Delta Basin. Multidisciplinary approaches – analysis of root-mean-square amplitude attribute, iterative integrated seismic interpretation and structural modeling, were employed in this study. Results reveal a massive northwest-southeast trending shale-cored detachment fold anticline containing numerous associated normal faults. This structure is interpreted to have been deformed by differential loading of the undercompacted, overpressured, and ductile Akata shale during syndepositional gravitational collapse of the Niger Delta slope. Crestal extension in the anticline resulted in a complex array of synthetic and antithetic normal faults, which include crossing-conjugate pairs. These conjugate structures could significantly affect permeability and reservoir performance. Crossing-conjugate faults have not previously been recognized in the Niger Delta, and similar structures may be present in other hydrocarbon-trapping structures in the basin. Also, the Miocene to Pliocene Agbada Formation reservoirs occur as part of a channelized fan system, mostly deposited as turbidites in an unconfined distributary environment, except one reservoir sand that occurs as channel sand within a submarine canyon that came across and eroded a previously deposited distributary fan complex, suggesting likely presence of prospective areas for hydrocarbon exploration southwest of the Freeman Field.
Presentation Date: Thursday, October 18, 2018
Start Time: 8:30:00 AM
Location: 210A (Anaheim Convention Center)
Presentation Type: Oral
The Way Ahead Interview invites senior figures who shape the E&P industry to share their wisdom, experience, and knowledge with the young professional community. For this issue, guest interviewers Fidan Traufetter and Margaret Åsly talk to Shell Vice President Ceri Powell, who shares her thoughts on issues such as mentoring, networking, and leadership and suggests strategies for achieving a gender-free profession.--Tony I actually wanted to break boundaries and become the first female stockbroker in the UK. However, it was the natural beauty of Pembrokeshire in southern Wales and, then, my high school geology teacher, who was passionate about the subject, that triggered a deep interest in geology. That encouraged me to read geology at University of Liverpool, which was followed up with a Shell-sponsored PhD in structural geology.
This publication presents how the flow assurance strategies of a sandstone oil field were optimised after numerous production upsets. It also uses economics to justify facilities enhancement projects for flow assurance. Field F is an offshore oil field with 210 feet water depth and eight subsea wells tied back to a third party FPSO vessel.
Field F was shut down for turnaround maintenance in 2015. After the field was brought back online, one of the production wells (F5) failed to flow. An evaluation of the reservoir, well, and facilities data suggested that there was a gas hydrate blockage in the pipeline. A subsea intervention vessel was then hired to execute a pipeline pigging and clean-out operation, which removed the gas hydrate, and restored oil production from the F5 well. To minimise oil production losses due to flow assurance issues, the asset team evaluated the viability of installing a test pipeline and a second methanol umbilical as facilities enhancement projects.
The pipeline clean-out operation delivered 5400 barrels of oil per day production to the asset. The feasibility study suggested that installing a second methanol umbilical and a test pipeline are economically attractive. It is recommended that the new methanol umbilical is installed and used to guarantee flow from the F5 well and the planned infill production wells. The test pipeline should also be installed and used for new well clean ups, well testing, well sampling, water chemistry analysis, tracer evaluation, and production optimisation.
This paper presents failure diagnosis and flow assurance remediation steps in a producing oil field, and aids the justification of test pipeline and methanol umbilical capacity enhancement projects.
This publication presents the lessons learnt during an operation to remove a hydrate blockage and reinstate oil production from a deep water well offshore Nigeria. It also uses economics to justify facilities projects for hydrate prevention and flow assurance. Field D is a deep water field with sandstone reservoir formations, oil, and gas-cap gas at initial conditions. It has been developed with over 10 subsea production and injection wells tied back to a Floating, Production, Storage, and Offloading (FPSO) vessel.
Field D was shut down for turnaround maintenance during the summer of 2016. After the field was restarted, one of the production wells (D2) failed to flow. An evaluation of the pressure and temperature data suggested that the well had a tubing restriction. This was attributed to hydrate formation and blockage caused by limited methanol injection capacity.
A number of attempts were made to restart the well with no success. A subsea intervention vessel was then hired to execute a clean out intervention operation, which restored oil production from the D2 well. The intervention operation added 26 000 barrels of oil per day production to the asset.
To minimise hydrate blockage and oil production losses, the asset team completed feasibility studies to evaluate the viability of installing a second methanol umbilical and a test/service pipeline. These studied indicated that installing both facilities enhancement projects are economically attractive.
This publication presents the lessons learnt during hydrate formation in a producing oil field, and outlines practical methods that can be used to justify facilities enhancement projects.
One of the major challenges of Logging-While-Drilling (LWD) Magnetic Resonance data acquisition is its limited logging speed. Typically, LWD Magnetic Resonance is logged at speeds of approximately 20m/hr (65ft/hr). Higher logging speeds will substantially reduce the vertical resolution of the data and prevent full polarization of the Hydrogen Protons in the formation, thus, introducing errors in the measurement of total porosity, fluid fractions, and permeability.
The axial motion (rate of penetration) of the magnetic resonance data has multiple effects on the acquired data. The main effects occur to the data during the polarization time, and the amplitude of the echoes during the Carr-Purcell-Meiboom-Gill (CPMG) pulse sequence time. The effects on the amplitude are broadly referred to as the flow effects.
During the drilling of a well in the Niger Delta, an operator needed to save rig cost by increasing the Rate of Penetration (ROP) for LWD Magnetic Resonance from 20m/hr to 40m/hr. This increased ROP caused an overestimation of the total porosity from magnetic resonance.
A newly introduced correction technique enables the compensation of effects due to high ROP on magnetic resonance data. This ROP correction methodology compensates flow and polarization effects. Total porosity and fluid fractions were corrected, resulting also in an updated Magnetic Resonance permeability index. Validation of the technique was accomplished by an accurate match of the corrected total porosity to results from offset wells.
This paper demonstrates the effect of a high rate of penetration on acquired LWD data. Details of flow and polarization effects, and the procedure for correcting these effects, making the data useable and accurate, are also presented.
The Magnetic Resonance (MR) method is based on a magnetic interaction of the magnetic moments of nuclei and externally applied magnetic fields. In the field of Magnetic Resonance Well Logging, only the hydrogen nuclei are of interest. Hydrocarbon and water contain a large number of hyrodrogen nuclei. The hydrogen nuclei possess the strongest magnetic moment. The hydrogen nucleus is a proton. The proton has a mass, an angular momentum and a charge. A spinning charge creates a magnetic moment. This magnetic moment allows the interaction with magnetic fields.